Catalysts, preparation of such catalysts, methods of using such catalysts, products obtained in such methods and uses of products obtained

ABSTRACT

A hydrocarbon composition is provided containing a total Ni/Fe/V content of at least 200 wtppm; a residue content of at least 0.2 grams per gram of hydrocarbon composition; a distillate content of at least 0.2 grams per gram of hydrocarbon composition; a sulfur content of at least 0.04 grams per gram of hydrocarbon composition; and a micro-carbon residue content of at least 0.06 grams per gram of hydrocarbon composition; and wherein the hydrocarbon composition has a viscosity of at most 100 cSt at 37.8° C.

This patent application claims the benefit of priority of U.S. patentapplication Ser. No. 12/421,771 filed Apr. 10, 2009, which claims thebenefit of priority of U.S. Provisional Application 61/043,941, filedApr. 10, 2008.

FIELD OF THE INVENTION

The present invention relates to catalysts, preparation of suchcatalysts, methods using such catalysts, products obtained in suchmethods and uses of products obtained.

BACKGROUND OF THE INVENTION

Crudes (whether in the form of crude oils, or solid or semi-solidhydrocarbons such as bitumen) that have one or more unsuitableproperties that do not allow the crudes to be economically transported,or processed using conventional facilities, are commonly referred to as“disadvantaged crudes”. Disadvantaged crudes may have a high viscositythat renders the disadvantaged crude undesirable for conventionaltransportation and/or treatment facilities. Disadvantaged crudes havinghigh viscosities, additionally, may also include hydrogen deficienthydrocarbons. When processing disadvantaged crudes having hydrogendeficient hydrocarbons, consistent quantities of hydrogen may need to beadded to inhibit coke formation, particularly if elevated temperaturesand high pressure are used to process the disadvantaged crude. Hydrogen,however, is costly to produce and/or costly to transport to treatmentfacilities.

Conventional methods of reducing the high viscosity of the disadvantagedcrude include contacting the disadvantaged crude at elevatedtemperatures and pressure with hydrogen in the presence of a catalyst.Deposits formed during processing may accumulate in the larger pores ofthe catalyst while viscosity and/or other properties are reduced bycontact of the feed with the active metals in the smaller pores of thecatalyst that the deposits and/or large compounds contributing toviscosity can not enter. Disadvantages of conventional catalysts arethat they require significant amounts of hydrogen in order to processthe hydrogen deficient hydrogens and the larger pores of the catalystbecome filled. Thus, the activity of the catalyst is diminished and thelife of the catalyst is reduced.

It would be desirable to have a method and/or a catalyst for reducingthe viscosity of disadvantaged crudes at elevated temperatures andminimal pressures for a prolonged period of time.

U.S. Pat. No. 6,554,994 to Reynolds et al., U.S. Pat. No. 6,436,280 toHarle et al., U.S. Pat. No. 5,928,501 to Sudhakar et al., U.S. Pat. No.4,937,222 to Angevine et al., U.S. Pat. No. 4,886,594 to Miller, U.S.Pat. No. 4,746,419 to Peck et al., U.S. Pat. No. 4,548,710 to Simpson,U.S. Pat. No. 4,525,472 to Morales et al., U.S. Pat. No. 4,499,203 toToulhoat et al., U.S. Pat. No. 4,389,301 to Dahlberg et al., and U.S.Pat. No. 4,191,636 to Fukui et al. describe various processes, systems,and catalysts for processing crudes and/or disadvantaged crudes.

U.S. Published Patent Application Nos. 20050133414 through 20050133418to Bhan et al.; 20050139518 through 20050139522 to Bhan et al.,20050145543 to Bhan et al., 20050150818 to Bhan et al., 20050155908 toBhan et al., 20050167320 to Bhan et al., 20050167324 through 20050167332to Bhan et al., 20050173301 through 20050173303 to Bhan et al.,20060060510 to Bhan; 20060231465 to Bhan; 20060231456 to Bhan;20060234876 to Bhan; 20060231457 to Bhan and 20060234877 to Bhan;20070000810 to Bhan et al.; 20070000808 to Bhan; 20070000811 to Bhan etal.; International Publication Nos. WO 2008/016969 and WO 2008/106979 toBhan; and U.S. patent application Ser. No. 11/866,909; 11/866,916;11/866,921 through Ser. No. 11/866,923; Ser. No. 11/866,926; Ser. No.11/866,929 and Ser. No. 11/855,932 to Bhan et al., filed Oct. 3, 2007,are related patent applications and describe various processes, systems,and catalysts for processing crudes and/or disadvantaged crudes.

U.S. patent application Ser. No. 11/866,926 describes in Example 24acatalyst that includes 0.02 grams of silica-alumina and 0.98 grams ofalumina per gram of support, nickel and molybdenum. The catalyst has amedian pore diameter of 155 Å, with at least 60% of the total number ofpores in the pore size distribution having a pore diameter within 28 Åof the median pore diameter and a surface area of 179 m²/g. Contact of ahydrocarbon feed with the catalyst and hydrogen at a temperature of 410°C. and a pressure of 3.8 MPa produces a crude product that has a reducedviscosity as compared to the hydrocarbon feed with a hydrogenconsumption of 35 Nm³/m³. The distribution of pores in the pore volumeof the catalyst is not discussed in Example 24. In Example 26, thecatalyst includes an alumina support, alumina oxide fines, andmolybdenum metal. The catalyst has a median pore diameter of 117 Å and abimodal distribution of pore diameter size of pores in the pore volume.Contact of the hydrocarbon feed at 400° C. and 3.8 MPa produces a crudeproduct that has a reduced viscosity. Hydrogen consumption was notdiscussed for the process using the catalyst of Example 26.

International Publication Nos. WO 2008/016969 and WO 2008/106979 to Bhandescribe catalysts and methods of using the catalyst to producehydrocarbon products having reduced pitch, sulfur, and MCR as comparedto the initial hydrocarbon feed. The catalysts described in Examples Iand III include a support having 2% silica in 98% alumina, andcatalytically active metals molybdenum and nickel. The catalysts havemedian pore diameters of less than 100 Å and surface areas ranging from133.5 m²/g to 332 m²/g. The hydrocarbon products produced by contact ofa heavy hydrocarbon with the catalysts at temperatures of 400° C. andpressures of 1900 psig (about 13 MPa) have reduced pitch and sulfurcontent as compared to the initial hydrocarbon feed. These publicationsdo not discuss reduction of viscosity at minimal pressures with minimalhydrogen consumption.

It would be advantageous to be able to convert a hydrocarbon feed havinga high viscosity, and therefore a low economic value, into a crudeproduct having a decreased viscosity by contacting the hydrocarbon feedwith minimal hydrogen consumption. The resulting crude product may,thereafter, be converted to selected hydrocarbon products usingconventional hydrotreating catalysts.

In addition it would be advantageous to have a catalyst for carrying outthe conversion of the hydrocarbon feed with a long useful life.

SUMMARY OF THE INVENTION

It has now been found that a hydrocarbon feed having a high viscositycan be converted into a crude product having a decreased viscosity withminimal hydrogen consumption by using a specific high surface areacatalyst. In addition it has been found that such a high surface areacatalyst has an increased useful life.

Accordingly, in some embodiments, the invention provides a catalystcomprising:

one or more metals from Column 6 of the Periodic Table and/or one ormore compounds of one or more metals from Column 6 of the Periodic Tableand a support; wherein the support comprises from 0.01 grams to 0.2 gramof silica and from 0.80 grams to 0.99 grams of alumina per gram ofsupport, and wherein the catalyst has a surface area of at least 340m²/g, a pore size distribution with a median pore diameter of at most100 Å, and at least 80% of its pore volume in pores having a porediameter of at most 300 Å.

Further, in some embodiments, the invention provides a catalystcomprising:

one or more metals from Column 6 of the Periodic Table and/or one ormore compounds of one or more metals from Column 6 of the Periodic Tableand a support; wherein the support comprises from 0.01 grams to 0.2 gramof silica and from 0.80 grams to 0.99 grams of alumina per gram ofsupport, and wherein the catalyst exhibits one or more peaks between 35degrees and 70 degrees, as determined by x-ray diffracton at 2-theta,and at least one of the peaks has a base width of at least 10 degrees.

Further, in some embodiments, the invention provides a method of makinga catalyst comprising:

co-mulling one or more metals from Column 6 of the Periodic Table and/orone or more compounds of one or more metals from Column 6 of thePeriodic Table with a support to provide a metal/support composition,wherein the support comprises from 0.01 grams to 0.2 gram of silica andfrom 0.8 grams to 0.99 grams of alumina per gram of support; and

calcining the metal/support composition at a temperature from 315° C. to760° C. to provide a calcined catalyst having a surface area of at least340 m²/g, a pore size distribution with a median pore diameter of atmost 100 Å, and at least 80% of its pore volume in pores having a porediameter of at most 300 Å, wherein surface area is as determined by ASTMMethod D3663 and pore diameters and pore volumes are as measured by ASTMMethod D4284.

Further, in some embodiments, the invention provides a method of makinga catalyst comprising:

co-mulling one or more metals from Column 6 of the Periodic Table and/orone or more compounds of one or more metals from Column 6 of thePeriodic Table with a support to provide a metal/support composition,wherein the support comprises from 0.01 grams to 0.2 gram of silica andfrom 0.8 grams to 0.99 grams of alumina per gram of support; and

calcining the metal/support composition at a temperature from 315° C. to760° C. to provide a calcined catalyst, wherein the Column 6 metalcatalyst exhibits one or more peaks between 35 degrees and 70 degrees,as determined by x-ray diffraction at 2-theta, and at least one of thepeaks has a base width of at least 10 degrees.

Further, in some embodiments, the invention provides a method ofproducing a crude product, comprising:

contacting a hydrocarbon feed with one or more catalysts to produce atotal product that includes the crude product, wherein at least one ofthe catalysts comprises one or more metals from Column 6 of the PeriodicTable and/or one or more compounds of one or more metals from Column 6of the Periodic Table and a support; wherein the support comprises from0.01 grams to 0.2 grams of silica and from 0.80 grams to 0.99 grams ofalumina per gram of support, and wherein the Column 6 metal catalyst hasa surface area of at least 340 m²/g, a pore size distribution with amedian pore diameter of at most 100 Å, and at least 80% of its porevolume in pores having a pore diameter of at most 300 Å; and

wherein surface area is as determined by ASTM Method D3663 and porediameters and pore volumes are as measured by ASTM Method D4284.

Further, in some embodiments, the invention provides a method ofproducing a crude product, comprising:

contacting a hydrocarbon feed with one or more catalysts for at least500 hours at a temperature of at least 200° C. and a pressure of atleast 3.5 MPa to produce a total product that includes the crudeproduct, wherein at least one of the catalysts comprises one or moremetals from Column 6 of the Periodic Table and/or one or more compoundsof one or more metals from Column 6 of the Periodic Table and a support;wherein the support comprises from 0.01 grams to 0.2 grams of silica andfrom 0.80 grams to 0.99 grams of alumina per gram of support, andwherein the Column 6 metal catalyst exhibits one or more peaks between35 degrees and 70 degrees, as determined by x-ray diffraction at2-theta, and at least one of the peaks has a base width of at least 10degrees.

Further, in some embodiments, the invention provides a crude productproduced by the methods as described above.

Further, in some embodiments, the invention provides a hydrocarboncomposition, comprising:

a total Ni/Fe/V content of at least 200 wtppm as determined by ASTMMethod D5708;

a residue content of at least 0.2 grams per gram of hydrocarboncomposition as determined by ASTM Method D5307;

a distillate content of at least 0.2 grams per gram of hydrocarboncomposition as determined by ASTM Method D5307;

a sulfur content of at least 0.04 grams per gram of hydrocarboncomposition as determined by ASTM Method D4294; and

a micro-carbon residue content of at least 0.06 grams per gram ofhydrocarbon composition, as determined by ASTM Method D4530; and whereinthe hydrocarbon composition has a viscosity of at most 100 cSt at 37.8°C. as determined by ASTM Method D445.

Further, in some embodiments, the invention provides a transportationfuel comprising one or more distillate fractions produced from thehydrocarbon composition as described above.

Further, in some embodiments, the invention provides a diluent producedfrom the hydrocarbon composition as described above.

In further embodiments, features from specific embodiments may becombined with features from other embodiments. For example, featuresfrom one embodiment may be combined with features from any of the otherembodiments.

In further embodiments, additional features may be added to the specificembodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is illustrated by the following figures:

FIG. 1 is a schematic of an embodiment of a contacting system.

FIG. 2 shows x-ray diffraction plots of intensity versus degrees 2-Thetaof molybdenum trioxide and an embodiment of a catalyst.

FIG. 3 is a graphical representation of a P-value of a crude productversus run time for various catalysts.

FIG. 4 is a graphical representation of inlet pressure of the reactorversus run time for various catalysts.

DETAILED DESCRIPTION OF THE INVENTION

Advantages of how a hydrocarbon feed with a high viscosity can beconverted into a crude product having a decreased viscosity with minimalhydrogen consumption by using a high surface area catalysts aredescribed herein. The high surface area catalysts, preparation of suchcatalysts, contacting a hydrocarbon feed with such catalysts, theproducts obtained from such processes, and the uses of the productsobtained are described herein. Certain embodiments of the inventions aredescribed herein in more detail.

Terms used herein are defined as follows.

“ASTM” refers to American Standard Testing and Materials.

“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity isas determined by ASTM Method D6822.

Atomic hydrogen percentage and atomic carbon percentage of thehydrocarbon feed and the crude product are as determined by ASTM MethodD5291.

“Bimodal catalyst” refers to a catalyst in which at least the majorityof the pore volume is distributed in two statistical distributions ofpore diameters, each statistical distribution having a significant peakwhen displayed on a pore volume versus pore diameter plot. For example,a bimodal catalyst may have 30% of its pore volume distributed in poreshaving a pore diameter between 50 and 100 Angstroms (with a peak showingat 80 A) and 25% of its pore volume distributed in pores having a porediameter between 300 and 350 A (with a peak showing at 320 A).

Boiling range distributions for the hydrocarbon feed, the total product,and/or the crude product are as determined by ASTM Method D5307 unlessotherwise mentioned.

“C₅ asphaltenes” refers to asphaltenes that are insoluble in n-pentane.C₅ asphaltenes content is as determined by ASTM Method D2007.

“C₇ asphaltenes” refers to asphaltenes that are insoluble in n-heptane.C₇ asphaltenes content is as determined by ASTM Method D3279.

“Column X metal(s)” refers to one or more metals of Column X of thePeriodic Table and/or one or more compounds of one or more metals ofColumn X of the Periodic Table, in which X corresponds to a columnnumber (for example, 1-12) of the Periodic Table. For example, “Column 6metal(s)” refers to one or more metals from Column 6 of the PeriodicTable and/or one or more compounds of one or more metals from Column 6of the Periodic Table.

“Column X element(s)” refers to one or more elements of Column X of thePeriodic Table, and/or one or more compounds of one or more elements ofColumn X of the Periodic Table, in which X corresponds to a columnnumber (for example, 13-18) of the Periodic Table. For example, “Column15 element(s)” refers to one or more elements from Column 15 of thePeriodic Table and/or one or more compounds of one or more elements fromColumn 15 of the Periodic Table.

In the scope of this application, weight of a metal from the PeriodicTable, weight of a compound of a metal from the Periodic Table, weightof an element from the Periodic Table, or weight of a compound of anelement from the Periodic Table is calculated as the weight of metal orthe weight of element. For example, if 0.1 grams of MoO₃ is used pergram of catalyst, the calculated weight of the molybdenum metal in thecatalyst is 0.067 grams of molybdenum metal per gram of catalyst.

“Comulling” refers to contacting, combining, or pulverizing of at leasttwo substances together such that at least two substances are mixedthrough mechanical and physical forces. Comulling can often form asubstantially uniform or homogeneous mixture. Comulling includes thecontacting of substances to yield a paste that can be extruded or formedinto extrudate particles, spheroids, pills, tablets, cylinders,irregular extrusions or loosely bound aggregates or clusters, by anyknown extrusion, molding tableting, pressing, pelletizing, or tumblingmethods. Comulling does not include impregnation methods in which aformed solid is immersed in a liquid or gas to absorb/adsorb componentsfrom the liquid or gas.

“Content” refers to the weight of a component in a substrate (forexample, a hydrocarbon feed, a total product, or a crude product)expressed as weight fraction or weight percentage based on the totalweight of the substrate. “Wtppm” refers to parts per million by weight.

“Distillate” refers to hydrocarbons with a boiling range distributionbetween 182° C. (360° F.) and 343° C. (650° F.) at 0.101 MPa. Distillatecontent is as determined by ASTM Method D5307.

“Heteroatoms” refers to oxygen, nitrogen, and/or sulfur contained in themolecular structure of a hydrocarbon. Heteroatoms content is asdetermined by ASTM Methods E385 for oxygen, D5762 for total nitrogen,and D4294 for sulfur. “Total basic nitrogen” refers to nitrogencompounds that have a pKa of less than 40. Basic nitrogen (“bN”) is asdetermined by ASTM Method D2896.

“Hydrogen source” refers to hydrogen, and/or a compound and/orcompounds, that when in the presence of a hydrocarbon feed and thecatalyst, react to provide hydrogen to compound(s) in the hydrocarbonfeed. A hydrogen source may include, but is not limited to, hydrocarbons(for example, C₁ to C₄ hydrocarbons such as methane, ethane, propane,and butane), water, or mixtures thereof. A mass balance may be conductedto assess the net amount of hydrogen provided to the compound(s) in thehydrocarbon feed.

“LHSV” refers to a volumetric liquid feed rate per total volume ofcatalyst and is expressed in hours (h⁻¹). Total volume of catalyst iscalculated by summation of all catalyst volumes in the contacting zones,as described herein.

“Liquid mixture” refers to a composition that includes one or morecompounds that are liquid at standard temperature and pressure (25° C.,0.101 MPa, hereinafter referred to as “STP”), or a composition thatincludes a combination of one of more compounds that are liquid at STPwith one or more compounds that are solids at STP.

“Metals in metal salts of organic acids” refer to alkali metals,alkaline-earth metals, zinc, arsenic, chromium, or combinations thereof.A content of metals in metal salts of organic acids is as determined byASTM Method D1318.

“Micro-Carbon Residue” (“MCR”) content refers to a quantity of carbonresidue remaining after evaporation and pyrolysis of a substrate. MCRcontent is as determined by ASTM Method D4530.

“Mineral-oxide fines” refers to oxides of metals ground to desiredparticle size. Examples of oxides of metals include, but are not limitedto, alumina, silica, silica-alumina, titanium oxide, zirconium oxide,magnesium oxide, or mixtures thereof.

“Molybdenum content in the hydrocarbon feed” refers to the content ofmolybdenum in the feed. The molybdenum content includes the amount ofinorganic molybdenum and organomolybdenum in the feed. Molybdenumcontent in the hydrocarbon feed is as determined by ASTM Method D5807.

“Monomodal catalyst” refers to a catalyst in which at least the majorityof the pore volume is distributed in one statistical distribution ofpore diameters, the statistical distribution having a significant peakwhen displayed on a pore volume versus pore diameter plot. For example,a monomodal catalyst may have 50% of its pore volume in pores having apore diameter between 70 Å and 300 Å (with a peak at 150 Å).

“Naphtha” refers to hydrocarbon components with a boiling rangedistribution between 38° C. (100° F.) and 182° C. (360° F.) at 0.101MPa. Naphtha content is as determined by ASTM Method D5307.

“Ni/V/Fe” refers to nickel, vanadium, iron, or combinations thereof.

“Ni/V/Fe content” refers to the content of nickel, vanadium, iron, orcombinations thereof. The Ni/V/Fe content includes inorganic nickel,vanadium and iron compounds and/or organonickel, organovanadium, andorganoiron compounds. The Ni/V/Fe content is as determined by ASTMMethod D5708.

“Nm³/m³” refers to normal cubic meters of gas per cubic meter ofhydrocarbon feed.

“Non-condensable gas” refers to components and/or mixtures of componentsthat are gases at STP.

“Organometallic” refers to compound that includes an organic compoundbonded or complexed with a metal of the Periodic Table. “Organometalliccontent” refers to the total content of metal in the organometalliccompounds. Organometallic content is as determined by ASTM Method D5807.

“Periodic Table” refers to the Periodic Table as specified by theInternational Union of Pure and Applied Chemistry (IUPAC), November2003.

“P (peptization) value” or “P-value” refers to a numeral value, whichrepresents the flocculation tendency of asphaltenes in the hydrocarbonfeed. P-Value is as determined by ASTM Method D7060.

“Pore diameter”, “median pore diameter”, and “pore volume” refer to porediameter, median pore diameter, and pore volume, as determined by ASTMMethod D4284 (mercury porosimetry at a contact angle equal to 140°). AMicromeritics® A9220 instrument (Micromeritics Inc., Norcross, Ga.,U.S.A.) may be used to determine these values.

“Residue” refers to components that have a boiling range distributionabove 538° C. (1000° F.), as determined by ASTM Method D5307.

“Sediment” refers to impurities and/or coke that are insoluble in thehydrocarbon feed/total product mixture. Sediment is as determined byASTM Method D4807. Sediment may also be determined by the Shell HotFiltration Test (“SHFST”) as described by Van Kernoort et al. in theJour. Inst. Pet., 1951, pages 596-604.

“SCFB” refers to standard cubic feet of gas per barrel of hydrocarbonfeed.

“Surface area” of a catalyst is as determined by ASTM Method D3663.

“VGO” refers to hydrocarbons with a boiling range distribution between343° C. (650° F.) and 538° C. (1000° F.) at 0.101 MPa. VGO content is asdetermined by ASTM Method D5307.

“Viscosity” refers to kinematic viscosity at 37.8° C. (100° F.).Viscosity is as determined using ASTM Method D445.

In the context of this application, it is to be understood that if thevalue obtained for a property of the substrate tested is outside oflimits of the test method, the test method may be modified and/orrecalibrated to test for such property.

“Hydrocarbon feed” refers to a feed that includes hydrocarbons.Hydrocarbon feed may include, but is not limited to, crudes,disadvantaged crudes, stabilized crudes, hydrocarbons obtained fromrefinery processes, or mixtures thereof. Examples of hydrocarbon feedobtained from refinery processes include, but are not limited to, longresidue, short residue, naphtha, gasoil and/or hydrocarbons boilingabove 538° C. (1000° F.), or mixtures thereof.

In one embodiment the hydrocarbon feed is a crude, herein also referredto as crude feed. Crude or crude feed refers to a feed of hydrocarbonswhich has been produced and/or retorted from hydrocarbon containingformations and which has not yet been distilled and/or fractionallydistilled in a treatment facility to produce multiple components withspecific boiling range distributions, such as atmospheric distillationmethods and/or vacuum distillation methods. Crudes may be solid,semi-solid, and/or liquid. Crudes may include for example coal, bitumen,tar sands or crude oil. The crude or crude feed may be stabilized toform a stabilized crude, also referred to as stabilized crude feed.Stabilization may include, but is not limited to, removal ofnon-condensable gases, water, salts, or combinations thereof from thecrude to form a stabilized crude. Such stabilization may often occur at,or proximate to, the production and/or retorting site.

Stabilized crudes have not been distilled and/or fractionally distilledin a treatment facility to produce multiple components with specificboiling range distributions (for example, naphtha, distillates, VGO,and/or lubricating oils). Distillation includes, but is not limited to,atmospheric distillation methods and/or vacuum distillation methods.Undistilled and/or unfractionated stabilized crudes may includecomponents that have a carbon number above 4 in quantities of at least0.5 grams of components per gram of crude. Examples of stabilized crudesinclude whole crudes, topped crudes, desalted crudes, desalted toppedcrudes, or combinations thereof.

“Topped” refers to a crude that has been treated such that at least someof the components that have a boiling point below 35° C. at 0.101 MPa(95° F. at 1 atm) have been removed. Topped crudes may have a content ofat most 0.1 grams, at most 0.05 grams, or at most 0.02 grams of suchcomponents per gram of the topped crude.

Some stabilized crudes have properties that allow the stabilized crudesto be transported to conventional treatment facilities by transportationcarriers (for example, pipelines, trucks, or ships). Other crudes haveone or more unsuitable properties that render them disadvantaged.

Disadvantaged crudes may be unacceptable to a transportation carrierand/or a treatment facility, thus imparting a low economic value to thedisadvantaged crude. The economic value may be such that a reservoirthat includes the disadvantaged crude is deemed too costly to produce,transport, and/or treat.

The properties of the hydrocarbon feed, such as for example the crudesor disadvantaged crudes may vary widely.

The hydrocarbon feed, such as for example a crude feed, may have aviscosity of at least 10 cSt at 37.8° C., at least 100 cSt, at least1000 cSt, or at least 2000 cSt at 37.8° C.

The hydrocarbon feed, such as for example a crude feed, may have an APIgravity at most 19, at most 15, or at most 10. It may further have anAPI gravity of at least 5.

The hydrocarbon feed, such as for example a crude feed, may have a totalNi/V/Fe content of at least 0.00002 grams or at least 0.0001 grams ofNi/V/Fe per gram of hydrocarbon feed;

The hydrocarbon feed, such as for example a crude feed, may have a totalheteroatoms content of at least 0.005 grams of heteroatoms per gram ofhydrocarbon feed;

In some embodiments, the hydrocarbon feed has at least 0.001 grams ofoxygen containing compounds per gram of hydrocarbon feed, and whereinthe crude product has a oxygen containing compounds content of at most90% of the hydrocarbon feed oxygen-containing compounds content, whereinoxygen is as determined by ASTM Method E385.

The hydrocarbon feed, such as for example a crude feed, may have aresidue content of at least 0.01 grams of residue per gram ofhydrocarbon feed. In some embodiments, the hydrocarbon or crude feed mayinclude, per gram of feed, at least 0.2 grams of residue, at least 0.3grams of residue, at least 0.5 grams of residue, or at least 0.9 gramsof residue.

The hydrocarbon feed, such as for example a crude feed, may have pergram of hydrocarbon feed, a sulfur content of at least 0.005, at least0.01, or at least 0.02 grams.

The hydrocarbon feed, such as for example a crude feed, may have pergram of hydrocarbon feed, a nitrogen content of at least 0.0005, atleast 0.001, or at least 0.002 grams. The hydrocarbon feed, such as forexample a crude feed, may have a C₅ asphaltenes content of at least 0.04grams or at least 0.08 grams of C₅ asphaltenes per gram of hydrocarbonfeed; and/or at least 0.02 grams or at least 0.04 grams of C₇asphaltenes per gram of hydrocarbon feed.

The hydrocarbon feed, such as for example a crude feed, may have a MCRcontent of at least 0.002 grams of MCR per gram of hydrocarbon feed

The hydrocarbon feed, such as for example a crude feed, may have acontent of metals in metal salts of organic acids of at least 0.00001grams of metals per gram of hydrocarbon feed

The hydrocarbon feed, such as for example a crude feed, may further havea molybdenum content of at least 0.1 wtppm;

The hydrocarbon feed, such as for example a crude feed, may further haveany kind of combination of the above mentioned properties.

The hydrocarbon feed, such as for example a crude feed, may include pergram of feed: at least 0.001 grams, at least 0.005 grams, or at least0.01 grams of hydrocarbons with a boiling range distribution between 95°C. and 200° C. at 0.101 MPa; at least 0.001 grams, at least 0.005 grams,or at least 0.01 grams of hydrocarbons with a boiling range distributionbetween 200° C. and 300° C. at 0.101 MPa; at least 0.001 grams, at least0.005 grams, or at least 0.01 grams of hydrocarbons with a boiling rangedistribution between 300° C. and 400° C. at 0.101 MPa; and at least0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution between 400° C. and 650°C. at 0.101 MPa.

In a further embodiment, the hydrocarbon feed, such as for example acrude feed, may include per gram of feed: at least 0.001 grams, at least0.005 grams, or at least 0.01 grams of hydrocarbons with a boiling rangedistribution of at most 100° C. at 0.101 MPa; at least 0.001 grams, atleast 0.005 grams, or at least 0.01 grams of hydrocarbons with a boilingrange distribution between 100° C. and 200° C. at 0.101 MPa; at least0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution between 200° C. and 300°C. at 0.101 MPa; at least 0.001 grams, at least 0.005 grams, or at least0.01 grams of hydrocarbons with a boiling range distribution between300° C. and 400° C. at 0.101 MPa; and at least 0.001 grams, at least0.005 grams, or at least 0.01 grams of hydrocarbons with a boiling rangedistribution between 400° C. and 650° C. at 0.101 MPa.

Some hydrocarbon feeds or crude feeds may include, per gram of feed, atleast 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution of at most 100° C. at0.101 MPa, in addition to higher boiling components. Typically, thedisadvantaged crude has, per gram of disadvantaged crude, a content ofsuch hydrocarbons of at most 0.2 grams or at most 0.1 grams.

Some hydrocarbon feeds or crude feeds may include, per gram of feed, atleast 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution of at least 200° C. at0.101 MPa.

Some hydrocarbon feeds or crude feeds may include, per gram of feed, atleast 0.001 grams, at least 0.005 grams, or at least 0.01 grams ofhydrocarbons with a boiling range distribution of at least 650° C.

Examples of crudes that might be treated using the processes describedherein include, but are not limited to, crudes from of the followingregions of the world: U.S. Gulf Coast and southern California, CanadaTar sands, Brazilian Santos and Campos basins, Egyptian Gulf of Suez,Chad, United Kingdom North Sea, Angola Offshore, Chinese Bohai Bay,Venezuelan Zulia, Malaysia, and Indonesia Sumatra.

Treatment of disadvantaged crudes may enhance the properties of thedisadvantaged crudes such that the crudes are acceptable fortransportation and/or treatment.

The hydrocarbon feed may be topped, as described herein. The crudeproduct resulting from treatment of the hydrocarbon feed, as describedherein, is generally suitable for transporting and/or treatment.Properties of the crude product produced as described herein are closerto the corresponding properties of West Texas Intermediate crude thanthe hydrocarbon feed, or closer to the corresponding properties of Brentcrude, than the hydrocarbon feed, thereby enhancing the economic valueof the hydrocarbon feed. Such crude product may be refined with less orno pre-treatment, thereby enhancing refining efficiencies. Pre-treatmentmay include desulfurization, demetallization, and/or atmosphericdistillation to remove impurities.

For example, in some embodiments, removal of at least a portion of theorganometallic compounds and/or metals from the hydrocarbon feed isperformed before the hydrocarbon feed is contacted with other catalysts.For example, a small amount of organomolybdenum and/or organocopper (forexample, at most 50 wtppm, at most 20 wtppm, or at most 10 wtppm) in ahydrocarbon feed may reduce the activity of a catalyst upon contact ofthe hydrocarbon feed with the catalyst.

Treatment of a hydrocarbon feed in accordance with embodiments describedherein may include contacting the hydrocarbon feed with the catalyst(s)in a contacting zone and/or combinations of two or more contactingzones. In a contacting zone, at least one property of a hydrocarbon feedmay be changed by contact of the hydrocarbon feed with one or morecatalysts relative to the same property of the hydrocarbon feed. In someembodiments, contacting is performed in the presence of a hydrogensource. In some embodiments, the hydrogen source is one or morehydrocarbons that, under certain contacting conditions, react to providerelatively small amounts of hydrogen to compound(s) in the hydrocarbonfeed.

In some embodiments the hydrocarbon feed may have a viscosity of atleast 100 cSt at 37.8° C., and contacting conditions may be controlledto produce the crude product; the crude product having a viscosity at37.8° C. of at most 50% of the viscosity of the hydrocarbon feed at37.8° C., and viscosity is as determined by ASTM Method D445

In some embodiments the hydrocarbon feed may have a copper content of atleast 1 wtppm, and contacting conditions may be controlled such that thecrude product has a copper content of at most 90% of the hydrocarbonfeed copper content, wherein the copper content is as determined by ASTMMethod D1318.

FIG. 1 is a schematic of contacting system 100 that includes contactingzone 102. The hydrocarbon feed enters upstream contacting zone 102 viahydrocarbon feed conduit 104. A contacting zone may be a reactor, aportion of a reactor, multiple portions of a reactor, or combinationsthereof. Examples of a contacting zone include a stacked bed reactor, afixed bed reactor, an ebullating bed reactor, a continuously stirredtank reactor (“CSTR”), a fluidized bed reactor, a spray reactor, and aliquid/liquid contactor. Configuration of one or more contacting zonesis described in U.S. Published Patent Application No. 20050133414 toBhan et al., which is incorporated herein by reference. In certainembodiments, the contacting system is on or coupled to an offshorefacility. Contact of the hydrocarbon feed with catalyst(s) in contactingsystem 100 may be a continuous process or a batch process.

The contacting zone may include one or more catalysts (for example, twocatalysts). In some embodiments, contact of the hydrocarbon feed with afirst catalyst of the two catalysts may reduce a portion of selectedmetals content and/or compounds that contribute to residue content ofthe hydrocarbon feed. Subsequent contact of the reduced metal/residuecontent hydrocarbon feed with the second catalyst decreases viscosityand/or increases API gravity. In other embodiments, viscosity, C₅asphaltenes, C₇ asphaltenes, organometallic content or combinations ofthese properties of the crude product change by at least 10% relative tothe same properties of the hydrocarbon feed after contact of thehydrocarbon feed with one or more catalysts.

In certain embodiments, a volume of catalyst in the contacting zone isin a range from 10 vol % to 60 vol %, 20 vol % to 50 vol %, or 30 vol %to 40 vol % of a total volume of hydrocarbon feed in the contactingzone. In some embodiments, a slurry of catalyst and hydrocarbon feed mayinclude from 0.001 grams to 10 grams, 0.005 grams to 5 grams, or 0.01grams to 3 grams of catalyst per 100 grams of hydrocarbon feed in thecontacting zone.

Contacting conditions in the contacting zone may include, but are notlimited to, temperature, pressure, hydrogen source flow, hydrocarbonfeed flow, or combinations thereof. Contacting conditions in someembodiments are controlled to produce a crude product with specificproperties. Preferably the contacting temperature is at least 200° C. Insome embodiments, temperature in a contacting zone may range from 350°C. to 450° C., from 360° C. to 440° C., or from 370° C. to 430° C. LHSVof the hydrocarbon feed will generally range from 0.1 h⁻¹ to 30 h⁻¹, 0.4h⁻¹ to 25 h⁻¹, 0.5 h⁻¹ to 20 h⁻¹, 1 h⁻¹ to 15 h⁻¹, 1.5 h⁻¹ to 10 h⁻¹, or2 h⁻¹ to 5 h⁻¹. In some embodiments, LHSV is at least 5 h⁻¹, at least 11h⁻¹, at least 15 h⁻¹, or at least 20 h⁻¹. A partial pressure of hydrogenin the contacting zone may range from 0.1 MPa to 8 MPa, 1 MPa to 7 MPa,2 MPa to 6 MPa, or 3 MPa to 5 MPa. In some embodiments the partialpressure of hydrogen may be at least 3.5 MPa. In some embodiments, apartial pressure of hydrogen may be at most 7 MPa, at most 6 MPa, atmost 5 MPa.

In embodiments in which the hydrogen source is supplied as a gas (forexample, hydrogen gas), a ratio (as determined at normal conditions of20° C. temperature and 1.013 bar pressure, herein below referred to asNm³/m³) of the gaseous hydrogen source to the hydrocarbon feed typicallyranges from 0.1 Nm³/m³ to 100,000 Nm³/m³, 0.5 Nm³/m³ to 10,000 Nm³/m³, 1Nm³/m³ to 8,000 Nm³/m³, 2 Nm³/m³ to 5,000 Nm³/m³, 5 Nm³/m³ to 3,000Nm³/m³, or 10 Nm³/m³ to 800 Nm³/m³ contacted with the catalyst(s). Thehydrogen source, in some embodiments, is combined with carrier gas(es)and recirculated through the contacting zone. Carrier gas may be, forexample, nitrogen, helium, and/or argon. The carrier gas may facilitateflow of the hydrocarbon feed and/or flow of the hydrogen source in thecontacting zone(s). The carrier gas may also enhance mixing in thecontacting zone(s). In some embodiments, a hydrogen source (for example,hydrogen, methane or ethane) may be used as a carrier gas andrecirculated through the contacting zone.

The hydrogen source may enter contacting zone 102 concurrently with thehydrocarbon feed via hydrocarbon feed conduit 104 or separately via gasconduit 106. In contacting zone 102, contact of the hydrocarbon feedwith a catalyst produces a total product that includes a crude product,and, in some embodiments, gas. In some embodiments, a carrier gas iscombined with the hydrocarbon feed and/or the hydrogen source in conduit106. The total product may exit contacting zone 102 and be transportedto other processing zones, storage vessels, or combinations thereof viaconduit 108.

In some embodiments, the total product may contain processing gas and/orgas formed during processing. Such gases may include, for example,hydrogen sulfide, carbon dioxide, carbon monoxide, excess gaseoushydrogen source, and/or a carrier gas. If necessary, the excess gas maybe separated from the total product and recycled to contacting system100, purified, transported to other processing zones, storage vessels,or combinations thereof. In some embodiments, gas produced during theprocess is at most 10 vol % based on total product, at most 5 vol %based on total product, or at most 1 vol % based the total productproduced. In some embodiments, minimal or non-detectable amounts of gasare produced during contact of the feed with the catalyst. In suchcases, the total product is considered the crude product.

In some embodiments, a crude (either topped or untopped) is producedfrom a reservoir and separated prior to contact with one or morecatalysts in contacting zone 102. During the separation process, atleast a portion of the hydrocarbon feed is separated using techniquesknown in the art (for example, sparging, membrane separation, pressurereduction) to produce the hydrocarbon feed. For example, water may be atleast partially separated from a disadvantaged crude. In anotherexample, components that have a boiling range distribution below 95° C.or below 100° C. may be at least partially separated from the crude toproduce the hydrocarbon feed. In some embodiments, at least a portion ofnaphtha and compounds more volatile than naphtha are separated from thedisadvantaged crude.

In some embodiments, the crude product is blended with a crude that isthe same as or different from the hydrocarbon feed. For example, thecrude product may be combined with a crude having a different viscositythereby resulting in a blended product having a viscosity that isbetween the viscosity of the crude product and the viscosity of thecrude. In another example, the crude product may be blended with crudehaving a TAN, viscosity and/or API gravity that is different, therebyproducing a product that has a selected property that is between thatselected property of the crude product and the crude. The blendedproduct may be suitable for transportation and/or treatment. In someembodiments, disadvantaged crude is separated to form the hydrocarbonfeed. The hydrocarbon feed is then contacted with one or more catalyststo change a selected property of the hydrocarbon feed to form a totalproduct. At least a portion of the total product and/or at least aportion of a crude product from the total product may blended with atleast a portion of the disadvantaged crude and/or a different crude toobtain a product having the desired properties.

In some embodiments, the crude product and/or the blended product aretransported to a refinery and distilled and/or fractionally distilled toproduce one or more hydrocarbon fractions. The hydrocarbon fractions maybe processed to produce commercial products such as transportation fuel,lubricants, or chemicals. Blending and separating of the disadvantagedcrude and/or hydrocarbon feed, total product and/or crude product isdescribed U.S. Published Patent Application No. 20050133414 to Bhan etal., which is incorporated herein by reference.

In certain embodiments, the crude product has at least 100 wtppm, atleast 150 wtppm, at least 200 wtppm or at least 220 wtppm of Ni/V/Fe. Insome embodiments, a total Ni/V/Fe content of the crude product is 70% to130%, 80% to 120%, or 90% to 110% of the Ni/V/Fe content of thehydrocarbon feed. In certain embodiments, the crude product has a totalNi/V/Fe content in a range from 0.1 to 5000 wtppm, from 1 to 1000 wtppm,from 10 to 500 wtppm, or from 100 to 350 wtppm.

In some embodiments, the crude product has a total molybdenum content ofat most 90%, at most 50%, at most 10%, at most 5%, or at most 3% of themolybdenum content of the hydrocarbon feed. In certain embodiments, thecrude product has a total molybdenum content ranging from 0.001 wtppm to1 wtppm, from 0.005 wtppm to 0.1 wtppm, or from 0.01 to 0.05 wtppm.

In some embodiments, the crude product has a copper content of at most90%, at most 50%, or at most 30% of the copper content of thehydrocarbon feed. In certain embodiments, the crude product has a totalcopper content ranging from 0.001 wtppm to 1 wtppm, or from 0.005 wtppmto 0.5 wtppm.

In certain embodiments, the crude product has a total content of metalsin metal salts of organic acids, per gram of crude product, in a rangefrom 0.1 wtppm to 50 wtppm, 3 wtppm to 20 wtppm grams, or 10 wtppm to 1wtppm of total metals in metal salt of organic acids per gram of crudeproduct.

In certain embodiments, API gravity of the crude product produced fromcontact of the hydrocarbon feed with catalyst, at the contactingconditions, is increased by at least 2, at least 3, at least 5, or atleast 10 relative to the API gravity of the hydrocarbon feed. In certainembodiments, API gravity of the crude product ranges from 7 to 40, 10 to30, or 12 to 25.

In certain embodiments, the crude product has a viscosity of at most90%, at most 80%, at most 50%, or at most 10% of the viscosity of thehydrocarbon feed. In some embodiments, the viscosity of the crudeproduct is at most 1000, at most 500, or at most 100 cSt.

In some embodiments, the sulfur content of the crude product is at most90%, at most 80% or at most 70% of the sulfur content of the hydrocarbonfeed. In some embodiments the sulfur content of the crude product is atleast 0.02 grams per gram of crude product. The sulfur content of thecrude product may range from 0.001 grams to 0.1 grams, from 0.005 to0.08 grams or from 0.01 to 0.06 grams per gram of crude product.

In some embodiments, the nitrogen content of the crude product is 70% to130%, 80% to 120%, or 90% to 110% of the nitrogen content of thehydrocarbon feed. In some embodiments the nitrogen content of the crudeproduct is at least 0.02 grams per gram of crude product. The nitrogencontent of the crude product may range from 0.001 grams to 0.1 grams,from 0.005 to 0.08 grams or from 0.01 to 0.05 grams per gram of crudeproduct.

In some embodiments, the crude product includes, in its molecularstructures, from 0.05 grams to 0.15 grams or from 0.09 grams to 0.13grams of hydrogen per gram of crude product. The crude product mayinclude, in its molecular structure, from 0.8 grams to 0.9 grams or from0.82 grams to 0.88 grams of carbon per gram of crude product. A ratio ofatomic hydrogen to atomic carbon (H/C) of the crude product may bewithin 70% to 130%, 80% to 120%, or 90% to 110% of the atomic H/C ratioof the hydrocarbon feed. A crude product atomic H/C ratio within 10% to30% of the hydrocarbon feed atomic H/C ratio indicates that uptakeand/or consumption of hydrogen in the process is relatively small,and/or that hydrogen is produced in situ.

The crude product includes components with a range of boiling points.

In some embodiments, the crude product has a distillate content of atleast 110%, at least 120%, or at least 130% of the distillate content ofthe hydrocarbon feed. The distillate content of the crude product maybe, per gram of crude product, in a range from 0.00001 grams to 0.6grams (0.001-60 wt %), 0.001 grams to 0.5 grams (0.1-50 wt %), or 0.01grams to 0.4 grams (1-40 wt %).

In certain embodiments, the crude product has a VGO content, boilingbetween 343° C. to 538° C. at 0.101 MPa, of 70% to 130%, 80% to 120%, or90% to 110% of the VGO content of the hydrocarbon feed. In someembodiments, the crude product has, per gram of crude product, a VGOcontent in a range from 0.00001 grams to 0.8 grams, 0.001 grams to 0.7grams, 0.01 grams to 0.6 grams, or 0.1 grams to 0.5 grams.

In some embodiments, the crude product has a residue content of at most90%, at most 80%, or at most 50% of the residue content of thehydrocarbon feed. The crude product may have, per gram of crude product,a residue content in a range from in a range from 0.00001 grams to 0.8grams, 0.001 grams to 0.7 grams, 0.01 grams to 0.6 grams, 0.05 grams to0.5 grams, or 0.1 to 0.3 grams.

In some embodiments, the crude product has a total C₅ and C₇ asphaltenescontent of at most 90%, at most 80%, at most 75%, or at most 50% of thetotal C₅ and C₇ asphaltenes content of the hydrocarbon feed. In otherembodiments, the C₅ asphaltenes content of the hydrocarbon feed is atleast 10%, at least 30%, or at least 40% of the C₅ asphaltenes contentof the hydrocarbon feed. In certain embodiments, the crude product has,per gram of hydrocarbon feed, a total C₅ and C₇ asphaltenes contentranging from 0.001 grams to 0.2 grams, 0.01 to 0.15 grams, or 0.05 gramsto 0.15 grams.

In certain embodiments, the crude product has a MCR content of at most95%, at most 90%, or at most 80% of the MCR content of the hydrocarbonfeed. In some embodiments, decreasing the C₅ asphaltenes content of thehydrocarbon feed while maintaining a relatively stable MCR content mayincrease the stability of the hydrocarbon feed/total product mixture.The crude product has, in some embodiments, from 0.0001 grams to 0.20grams, 0.005 grams to 0.15 grams, or 0.01 grams to 0.010 grams of MCRper gram of crude product.

In certain embodiments, the crude product is a hydrocarbon compositionthat has a total Ni/Fe/V content of at least 200 wtppm; a residuecontent of at least 0.2 grams per gram of hydrocarbon composition; adistillate content of at least 0.2 grams per gram of hydrocarboncomposition; a sulfur content of at least 0.04 grams per gram ofhydrocarbon composition; and a micro-carbon residue content of at least0.06 grams per gram of hydrocarbon composition; and a viscosity of atmost 100 cSt at 37.8° C.

It may be desirable to only selectively reduce one or more components(for example, viscosity) in a hydrocarbon feed without significantlychanging the amount of sulfur and/or Ni/V/Fe in the hydrocarbon feed. Inthis manner, hydrogen uptake during contacting may be “concentrated” onviscosity reduction, and not reduction of other components. Reduction ofsulfur typically requires the catalyst to include additional metals (forexample, nickel and/or cobalt). Conversion of hydrocarbons that containsulfur and/or other heteroatoms may attribute to hydrogen consumptionduring processing. Since less of such hydrogen is also being used toreduce other components in the hydrocarbon feed, the amount of hydrogenused during the process may be minimized. A catalyst having minimalamount of Columns 7-10 metal(s), a high surface area, and a selectedpore distribution may assist in reduction of components in a hydrocarbonfeed that contribute to high viscosity to produce a crude product withreduced viscosity as compared to the hydrocarbon feed. In someembodiments, the crude product may have a minimal change in otherproperties as compared to the hydrocarbon feed. The produced crudeproduct may have acceptable properties that allow it to be transportedto treatment facilities and/or other processing units. For example, ahydrocarbon feed may have a high viscosity, but a Ni/V/Fe and/or sulfurcontent that is acceptable to meet treatment and/or transportationspecifications. Such hydrocarbon feed may be more efficiently treatedwith the catalyst described herein by reducing viscosity without alsoreducing Ni/V/Fe or sulfur content.

In some embodiments, contact of a hydrocarbon feed using the catalystsdescribed herein at temperatures of at least 200° C. and pressures of atmost 5 MPa or at most 7 MPa produces a crude product that has aviscosity of at most 100 cSt at 37.8° C., a total Ni/Fe/V content of atleast 200 wtppm, a residue content of at least 0.2 grams per gram ofcrude product, a distillate content of at least 0.2 grams per gram ofcrude product, a sulfur content of at least 0.04 grams per gram of crudeproduct, and a micro-carbon residue content of at least 0.06 grams pergram of crude product.

Catalysts used in one or more embodiments of the inventions may includeone or more bulk metals and/or one or more metals on a support. Themetals may be in elemental form or in the form of a compound of themetal. The catalysts described herein may be introduced into thecontacting zone as a precursor, and then become active as a catalyst inthe contacting zone (for example, when sulfur and/or a hydrocarbon feedcontaining sulfur is contacted with the precursor).

In certain embodiments, the catalyst includes Column 6 metal(s). Column6 metal(s) include, but are not limited to, chromium, molybdenum,tungsten. The catalyst may have, per gram of catalyst, a total Column 6metal(s) content of at least 0.00001, at least 0.01 grams, at least 0.02grams and/or in a range from 0.0001 grams to 0.6 grams, 0.001 grams to0.3 grams, 0.005 grams to 0.1 grams, or 0.01 grams to 0.08 grams. Insome embodiments, the catalyst includes from 0.0001 grams to 0.06 gramsof Column 6 metal(s) per gram of catalyst. In some embodiments,compounds of Column 6 metal(s) include oxides such as molybdenumtrioxide and/or tungsten trioxide. In certain embodiments, the catalystincludes only Column 6 metals or only Column 6 compounds. In anembodiment, the catalyst includes only molybdenum and/or molybdenumoxides.

In some embodiments, the catalyst includes a combination of Column 6metal(s) with one or more metals from Columns 7-10. Columns 7-10metal(s) include, but are not limited to, manganese, technetium,rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium,iridium, platinum, or mixtures thereof. The catalyst may have, per gramof catalyst, a total Columns 6-10 metal(s) content in a range from atleast 0.0001 grams, at least 0.001 grams, at least 0.01 grams, or in arange of 0.0001 grams to 0.6 grams, 0.001 grams to 0.3 grams, 0.005grams to 0.1 grams, or 0.01 grams to 0.08 grams. In some embodiments,the catalyst includes Column 15 element(s) in addition to the Columns6-10 metal(s). In some embodiments, the catalyst has at most 0.03 grams,at most 0.02 grams or 0.01 grams of Columns 7-10 metals per gram ofcatalyst. In some embodiments, the catalyst does not include Columns7-10 metals.

In some embodiments the catalyst contains at most 0.03 grams, at most0.01 grams, or at most 0.005 grams per gram of catalyst of one or moremetals from Columns 9 and 10 of the Periodic Table and/or one or morecompounds of one or more compounds of one or more metals from Columns 9and 10 of the Periodic Table. In a still further embodiment the catalystdoes not include any such metals.

A molar ratio of Column 6 metal to Columns 7-10 metal in the catalystmay be in a range from 0.1 to 20, 1 to 10, or 2 to 5. In someembodiments, the catalyst includes Column 15 element(s) in addition tothe combination of Column 6 metal(s) with one or more metals fromColumns 7-10. In other embodiments, the catalyst includes Column 6metal(s) and Column 10 metal(s). A molar ratio of the total Column 10metal to the total Column 6 metal in the catalyst may be in a range from1 to 10, or from 2 to 5.

In some embodiments, the catalyst includes Column 15 element(s) inaddition to the Column 6 metal(s). Examples of Column 15 elementsinclude phosphorus. The catalyst may have a total Column 15 elementcontent, per gram of catalyst, in range from 0.000001 grams to 0.1grams, 0.00001 grams to 0.06 grams, 0.00005 grams to 0.03 grams, or0.0001 grams to 0.001 grams.

In some embodiments, Column 6 metal(s) alone or in combination withColumns 7-10 metal(s) are incorporated with a support to form thecatalyst. In certain embodiments, Column 15 element(s) are alsoincorporated with a support to form the catalyst.

The support includes silica and alumina. In embodiments in which themetal(s) and/or element(s) are supported, the weight of the catalystincludes all support, all metal(s), and all element(s). The support maybe porous.

In some embodiments, the support includes silica and alumina incombination with limited amounts of other refractory oxides, porouscarbon based materials, zeolites, or combinations thereof. Refractoryoxides may include, but are not limited to, alumina, silica,silica-alumina, titanium oxide, zirconium oxide, magnesium oxide, ormixtures thereof. Supports may be obtained from a commercialmanufacturer such as Criterion Catalysts and Technologies LP (Houston,Tex., U.S.A.). Porous carbon based materials include, but are notlimited to, activated carbon and/or porous graphite. Examples ofzeolites include Y-zeolites, beta zeolites, mordenite zeolites, ZSM-5zeolites, and ferrierite zeolites.

Zeolites may be obtained from a commercial manufacturer such as Zeolyst(Valley Forge, Pa., U.S.A.).

In certain embodiments, the support includes gamma alumina, deltaalumina, alpha alumina, or combinations thereof. In some embodiments,the support includes from 0.0001 grams to 0.20 grams, 0.001 grams to0.11 grams, or 0.01 grams to 0.05 grams of silica; and 0.80 grams to0.9999 grams, 0.90 grams to 0.999 grams, or 0.95 to 0.97 grams ofalumina per gram of support. Incorporation of silica into the supportmay assist in dispersing catalytic metals (for example, Column 6metal(s) or Column 6 metals in combination with Columns 7-10 metal(s))throughout the support. Dispersion of catalytic metals throughout thesupport may allow formation of a catalyst having a surface area of atleast 340 m²/g, at least 360 m²/g, or at least 400 m²/g.

Catalyst that have a large surface area with a minimal amount ofcatalytic metal (for example Column 6 metal(s)) on the surface of thecatalyst may be prepared by comulling the catalytic metal with asupport. Comulling of the support and Column 6 metal(s) may form asubstantially uniform or homogeneous mixture. In some embodiments, waterand/or solvent may be added during the comulling to facilitate formingthe mixture into a paste that may be extruded or formed into extrudateparticles, spheroids, pills, tablets, cylinders, irregular extrusions orloosely bound aggregates or clusters, by any known extrusion, moldingtableting, pressing, pelletizing, or tumbling methods.

Column 6 metal(s) and a support may be contacted with suitable mixingequipment. Examples of suitable mixing equipment include tumblers,stationary shells or troughs, Muller mixers (for example, batch type orcontinuous type), impact mixers, and any other generally known mixer, orgenerally known device, that will suitably provide the Column 6metal(s)/support mixture. In certain embodiments, the materials aremixed until the Column 6 metal(s) is (are) substantially homogeneouslydispersed in the support. Dispersion of the Column 6 metal(s) in thesupport may inhibit coking of the Column 6 metal(s) at high temperaturesand/or pressures, thus allowing hydrocarbon feeds containing significantamounts of residue and/or high viscosities to be processed at rates,temperatures and pressures not obtainable by using conventionalcatalysts made using impregnation techniques. In some embodiments,comulling of a support containing silica and Column 6 metal(s) forms asmoother catalyst surface.

Combining the Column 6 metal(s) with the support allows (for example,comulling, in contrast to impregnation of a support) at least a portionof the metal(s) to reside under the surface of the embedded metalcatalyst (for example, embedded in the support), leading to less metalon the surface than would otherwise occur in the unembedded metalcatalyst. In some embodiments, having less metal on the surface of thecatalyst extends the life and/or catalytic activity of the catalyst byallowing at least a portion of the metal to move to the surface of thecatalyst during use. The metals may move to the surface of the catalystthrough erosion of the surface of the catalyst during contact of thecatalyst with a hydrocarbon feed.

Without wishing to bound by any kind of theory, it is thought that theaddition intercalation and/or mixing of the components of the catalystsmay change the structured order of the Column 6 metal in the Column 6oxide crystal structure to a substantially random order of Column 6metal in the crystal structure of the embedded catalyst. The order ofthe Column 6 metal may be determined using powder x-ray diffractionmethods. The order of elemental metal in the catalyst relative to theorder of elemental metal in the metal oxide may be determined bycomparing the order of the Column 6 metal peak in an x-ray diffractionspectrum of the Column 6 oxide to the order of the Column 6 metal peakin an x-ray diffraction spectrum of the catalyst. From broadening and/orabsence of patterns associated with Column 6 metal in an x-raydiffraction spectrum, it is possible to estimate that the Column 6metal(s) are substantially randomly ordered in the crystal structure.For example, molybdenum trioxide and the silica/alumina support having amedian pore diameter of at least 180 Å may be combined to form analumina/molybdenum trioxide mixture. Molybdenum trioxide has a definitex-ray diffraction pattern (for example, definite D₀₀₁, D₀₀₂ and/or D₀₀₃peaks). The support/molybdenum trioxide mixture may be heat treated at atemperature of at least 316° C. (600° F.), at least 427° C. (800° F.),or at least 538° C. (1000° F.) to produce a catalyst that does notexhibit a pattern for molybdenum dioxide in an x-ray diffractionspectrum (for example, an absence of the D₀₀₁ peak).

In some embodiments, contacting a Column 6 metal(s)/support mixtureforms a Column 6 metal/support mixture. In some embodiments, an acidand/or water is added to the Column 6 metal/support mixture to assist information of the Column 6 metal/support mixture into particles. Thewater and/or dilute acid are added in such amounts and by such methodsas required to give the Column 6 metal/support mixture a desiredconsistency suitable to be formed into particles. Examples of acidsinclude, but are not limited to, nitric acid, acetic acid, sulfuricacid, and hydrochloric acid.

The Column 6 metal/support mixture may be formed into particles usingknown techniques in the art such as an extruder. The particles(extrudates) may be cut using known catalyst cutting methods to formparticles. The particles may be heat treated at a temperature in a rangefrom 65° C. to 260° C. or from 85° C. to 235° C. for a period of time(for example, for 0.5-8 hours) and/or until the moisture content of theparticle has reached a desired level.

The Column 6 metal(s)/support and/or the Column 6 metal(s)/supportparticles may be heat treated (calcined) in the presence of hot airand/or oxygen containing air at a temperature in a range between 315° C.and 760° C., between 535° C. and 760° C., or between 500° C. and 650° C.to remove volatile matter such that at least a portion of the Columns6-10 metals are converted to the corresponding metal oxide. Thetemperature conditions at which the particles are calcined may be suchthat the pore structure of the final calcined mixture is controlled toform the pore structure and surface areas of the catalysts describedherein. Calcining at temperatures greater than 760° C. may increase thepore volume of the catalyst, thus change the distribution of pores andthe surface area such that the catalyst is not as effective in removingcompounds that contribute to high viscosity and/or residue. In oneembodiment Column 6 metal(s)/support composition may be calcined at atemperature in the range from 315° C. to 675° C., in the range from 400°C. to 650° C., or in the range from 450° C. to 600° C., in order tocreate a large surface area.

A catalyst with dispersed metals may advantageously have a longer lifethan the conventional hydroprocessing catalyst, at elevated temperaturesand lower pressures (for example, temperatures of at least 200° C. or atleast 400° C. and pressures of at most 7 MPa, at most 5 MPa, or at most3.8 MPa). The selected dispersed metal catalyst may allow a process tobe run without recharging or changing the catalyst, thus cost ofprocessing the hydrocarbon feed may be economically advantageous. Thecatalyst may remain active during contact with a hydrocarbon feed for atleast 500 hours, at least 1000 hours, at least 2000 hours, at least 3000hours, at least 6000 hours or at least 9000 hours.

In some embodiments, catalysts may be characterized by pore structure.Various pore structure parameters include, but are not limited to, porediameter, pore volume, surface areas, or combinations thereof. Thecatalyst may have a distribution of total quantity of pore sizes versuspore diameters. The median pore diameter of the pore size distributionmay be in a range from 30 Å to 100 Å, 50 Å to 90 Å, or 60 Å to 80 Å.

The catalyst may have a pore size distribution with a median porediameter of at least 60 Å, at least 90 Å, or at most 100 Å. In someembodiments, the catalyst has a pore size distribution with a medianpore diameter in a range from 30 Å to 100 Å, 50 Å to 90 Å, or 60 Å to 80Å, with at least 60% of a total number of pores in the pore sizedistribution having a pore diameter within 50 Å, 40 Å, or 30 Å of themedian pore diameter.

In some embodiments, pore volume of pores in the catalyst may be atleast 0.3 cm³/g, at least 0.7 cm³/g, or at most 1.2 cm³/g. In certainembodiments, pore volume of pores in the catalyst may range from 0.3cm³/g to 0.99 cm³/g, 0.4 cm³/g to 0.8 cm³/g, or 0.5 cm³/g to 0.7 cm³/g.

The pore volume of the catalyst includes pores having a pore diameterbetween 1 Å and 5000 Å and pores having a pore diameter greater than5000 Å. In some embodiments, the catalyst has a majority of its porevolume in pores having a pore diameter of at most 300 Å, at most 200 Å,or at most 100 Å. In some embodiments, the catalyst has at most 80% ofits pore volume in pores having a pore diameter of at most 100 Å, atleast 5% of its pore volume in pores having a pore diameter of atbetween 100 Å and 300 Å, with the balance of the pore volume being inpores having a pore diameter of at least 300 Å.

In some embodiments, the catalyst may have at least 90% or at least 95%of its pore volume in pores having a pore diameter of at most 300 Å.

In some embodiments, the catalyst may have at most 5% of its pore volumein pores having a pore diameter of at least 5000 Å.

Such a catalyst may have a pore volume between 0.5 cc/g and 1.0 cc/g anda surface area of at least 340 m²/g. In some embodiments, the catalysthaving a pore size distribution with a median pore diameter in a rangefrom about 50 Å to 100 Å, may have a surface areas of at least 340 m²/g.Such surface area may be in a range from 340 m²/g to 500 m²/g, 350 m²/gto 450 m²/g, or 375 m²/g to 425 m²/g.

Catalysts having specific surface topology, large surface areas, andpore distributions described above may exhibit enhanced run times incommercial applications at low pressures and elevated temperatures. Forexample, the catalyst remains catalytically active after at least 1 yearof run time. The enhanced run times may be attributed to the highsurface area of the catalyst and/or the narrow distribution of porediameter in the pore volume of the catalyst. Thus, the metals of thecatalyst remain exposed for longer periods of time and plugging of thepores of the catalyst is minimal. The high surface area and selecteddistribution of pores in the pore volume of the catalyst allowsprocessing of high viscosity and/or high residue crudes that would notbe able to be processed with conventional catalysts having the same poredistribution, but smaller surface area. Calcining a comulled catalyst attemperatures ranging from 315° C. to 675° C., in the range from 400° C.to 650° C., or in the range from 450° C. to 600° C. may facilitateformation of pores having similar pore diameters and narrow poredistributions with large surface areas.

In certain embodiments, the catalyst exists in shaped forms, forexample, pellets, cylinders, and/or extrudates. In some embodiments, thecatalyst and/or the catalyst precursor is sulfided to form metalsulfides (prior to use) using techniques known in the art (for example,ACTICAT™ process, CRI International, Inc.). In some embodiments, thecatalyst may be dried then sulfided. Alternatively, the catalyst may besulfided in situ by contact of the catalyst with a hydrocarbon feed thatincludes sulfur-containing compounds. In-situ sulfurization may utilizeeither gaseous hydrogen sulfide in the presence of hydrogen, orliquid-phase sulfurizing agents such as organosulfur compounds(including alkylsulfides, polysulfides, thiols, and sulfoxides). Ex-situsulfurization processes are described in U.S. Pat. No. 5,468,372 toSeamans et al., and U.S. Pat. No. 5,688,736 to Seamans et al., all ofwhich are incorporated herein by reference.

In commercial applications, after sulfidation of the hydroprocessingcatalysts, the hydroprocessing catalysts are typically heated to 400° C.over one or more months to control the generation of hydrogen sulfide.Slow heating of hydroprocessing catalysts may inhibit deactivation ofthe catalyst. The catalyst described herein has enhanced stability inthe presence of hydrogen sulfide when heated to 400° C. in less thanthree weeks. Being able to preheat the catalyst over a shorter period oftime may increase the amount of hydrocarbon feed that can be processedthrough a contacting system.

In certain embodiments, the catalyst of the invention is obtainable byco-mulling Column 6 metal(s) with a support. Co-mulling the Column 6metal(s) with the support may form a mixture or a substantiallyhomogeneous mixture. In some embodiments, the mixture may be extrudedand/or dried. The mixture may be calcined at a temperature of between535° C. and 700° C. to produce the catalyst.

The support may include from 0.001 grams to 0.2 grams of silica and 0.80grams to 0.999 grams of alumina, or from 0.001 grams to 0.1 grams ofsilica and 0.90 gram to 0.999 grams of alumina per gram of catalyst. Insome embodiments, the mixture may be dried and calcined at a temperatureof between 315° C. and 760° C. to produce the catalyst.

The catalyst may have from 0.001 grams to 0.3 grams, 0.005 grams to 0.2grams, or 0.01 grams to 0.1 grams of Columns 6 metal(s) per gram ofcatalyst. In some embodiments, the catalyst may include at most 0.1grams of Column 6 metal(s) per gram of catalyst.

Without wishing to bound by any kind of theory, it is thought that theaddition of silica to the support may allow Columns 6 metal(s) to remaindispersed throughout the support while being heated to elevatedtemperatures (for example, temperatures of at least 315° C., at least335° C., at least 375° C., or at least 425° C.).

In some embodiments, the catalyst is monomodal. Such comulling of metaland support, followed by calcination, may produce a monomodal catalysthaving a pore size distribution with a median pore diameter of at most100 Å, with at least 80% of its pore volume in pores having a porediameter of at most 300 Å. The catalyst may have a surface area of atleast 340 m²/g. The catalyst may have a pore volume from 0.5 cc/g to 0.9cc/g. In some embodiments, the catalyst may exhibit one or more peaksbetween 35 degrees and 70 degrees, and at least one of the peaks has abase width of at least 10 degrees, as determined by x-ray diffraction at2-theta.

This catalyst reduces at least a portion of the components thatcontribute to higher viscosities and/or a portion of the components thatcontribute to copper content without significant reduction in sulfurand/or Ni/Fe/V content. Treatment of the hydrocarbon feed with a Column6 metal catalyst that contains none or a minimal amount of Columns 9 and10 metals may be economically advantageous since it allows production ofa product with reduced viscosity and minimal desulfurization and/ordemetallation relative to the same properties of the hydrocarbon feed.

Using the catalyst(s) of this application and controlling operatingconditions may allow a crude product to be produced that has selectedproperties changed relative to the hydrocarbon feed while otherproperties of the hydrocarbon feed are not significantly changed. Theresulting crude product may have enhanced properties relative to thehydrocarbon feed and, thus, be more acceptable for transportation and/orrefining.

The catalyst of the application may remove components that contribute toa decrease in the life of other catalysts in the system from thehydrocarbon feed. For example, reducing the viscosity of hydrocarbonfeed/total product mixture relative to the hydrocarbon feed may inhibitplugging of other catalysts positioned downstream, and thus, increasesthe length of time the contacting system may be operated withoutreplenishment of catalysts.

The catalyst of the application may produce a crude product with a lowerviscosity as compared to the hydrocarbon feed with minimal amount ofhydrogen consumption. In some embodiments, at contacting conditions at atotal pressure of 3.5 MPa, hydrogen consumption may be at most 30Nm³/m³, at most 25 Nm³/m³, or at most 10 Nm³/m³. In some embodiments, atcontacting conditions at a total pressure of 3.5 MPa, hydrogenconsumption may be from 1 Nm³/m³ to 30 Nm³/m³, from 1 Nm³/m³ to 30Nm³/m³, from 5 Nm³/m³ to 25 Nm³/m³, or from 10 Nm³/m³ to 20 Nm³/m³.

In some embodiments contacting conditions may be controlled to producethe crude product at a partial pressure of hydrogen at a pressure ofmost 7 MPa, wherein hydrogen consumption is at most 30 Nm³/m³. In otherembodiments contacting conditions may be controlled to produce the crudeproduct at a partial pressure of hydrogen at a pressure of most 7 MPaand at a temperature of least 200° C.

In some embodiments, the catalyst of the application may be used incombination with other catalysts. An example of another catalyst is acatalyst that includes supported catalyst fines and/or mineral oxidefines. Such catalysts are described in U.S. patent applications entitled“A Catalyst and Process for the Manufacture of Ultra-Low SulfurDistillate Product” and “A Highly Stable Heavy HydrocarbonHydrodesulfurization Catalyst and Method of Making and Use Thereof” toBhan; and International Application No. WO 02/32570 to Bhan.

Arrangement of two or more catalysts in a selected sequence may controlthe sequence of property improvements for the feed. For example, acatalyst having a surface area of at most 300 Å as described herein maybe placed upstream of the catalyst having a surface area of at least 340Å. Treatment of the hydrocarbon feed with hydrogen in the presence ofthe lower surface area catalyst may reduce a portion of the componentsthat contribute to residue, at least a portion of the components thatcontribute to high viscosity at least a portion of the C₅ asphaltenes,or at least a portion of metals in metal salts of organic acids. Contactof the treated hydrocarbon feed with the higher surface area catalystmay further reduce viscosity, copper content, vanadium content, and/ormetals in metal salts of organic acids.

Arrangement and/or selection of the catalysts may, in some embodiments,improve the useable life of the catalysts and/or the stability of thehydrocarbon feed/total product mixture. Improvement of a catalyst lifeand/or stability of the hydrocarbon feed/total product mixture duringprocessing may allow a contacting system to operate for at least 3months, at least 6 months, or at least 1 year without replacement of thecatalyst in the contacting zone.

Combinations of the catalysts of described herein allows reduction of:viscosity, at least a portion of the C₅ asphaltenes, at least a portionof the metals in metal salts of organic acids, at least a portion of theresidue, or combinations thereof, from the hydrocarbon feed, beforeother properties of the hydrocarbon feed are changed, while maintainingthe stability of the hydrocarbon feed/total product mixture duringprocessing (for example, maintaining a hydrocarbon feed P-value of above1.0). The ability to selectively change properties of the hydrocarbonfeed may allow the stability of the hydrocarbon feed/total productmixture to be maintained during processing.

In some embodiments, commercially available catalysts may be positioneddownstream of the catalysts of the invention to reduce selectedproperties of the feed. For example, a demetallization catalyst may bepositioned downstream of the first catalyst to reduce the Ni/V/Fecontent of the crude product as compared to Ni/V/Fe of the feed. Adesulfurization catalyst may be positioned downstream of thedemetallization catalyst to reduce the heteroatom content of the crudeproduct as compared to the heteroatom content of the feed. Examples ofcommercial catalysts include HDS3; HDS22; HDN60; C234; C311; C344; C411;C424; C344; C444; C447; C454; C448; C524; C534; DC2531; DN120; DN130;DN140; DN190; DN200; DN800; DN2118; DN2318; DN3100; DN3110; DN3300;DN3310; DN3330; RC400; RC410; RN412; RN400; RN420; RN440; RN450; RN650;RN5210; RN5610; RN5650; RM430; RM5030; Z603; Z623; Z673: Z703; Z713;Z723; Z753; and Z763, which are available from CRI International, Inc.(Houston, Tex., U.S.A.).

Reduction in net hydrogen uptake by the hydrocarbon feed may produce acrude product that has a boiling range distribution similar to theboiling point distribution of the hydrocarbon feed. The atomic H/C ratioof the crude product may also only change by relatively small amounts ascompared to the atomic H/C ratio of the hydrocarbon feed.

In some embodiments, catalyst selection and/or order of catalysts incombination with controlled contacting conditions (for example,temperature and/or hydrocarbon feed flow rate) may assist in reducinghydrogen uptake by the hydrocarbon feed, maintaining hydrocarbonfeed/total product mixture stability during processing, and changing oneor more properties of the crude product relative to the respectiveproperties of the hydrocarbon feed. Stability of the hydrocarbonfeed/total product mixture may be affected by various phases separatingfrom the hydrocarbon feed/total product mixture. Phase separation may becaused by, for example, insolubility of the hydrocarbon feed and/orcrude product in the hydrocarbon feed/total product mixture,flocculation of asphaltenes from the hydrocarbon feed/total productmixture, precipitation of components from the hydrocarbon feed/totalproduct mixture, or combinations thereof.

At certain times during the contacting period, the concentration ofhydrocarbon feed and/or total product in the hydrocarbon feed/totalproduct mixture may change. As the concentration of the total product inthe hydrocarbon feed/total product mixture changes due to formation ofthe crude product, solubility of the components of the hydrocarbon feedand/or components of the total product in the hydrocarbon feed/totalproduct mixture tends to change. For example, the hydrocarbon feed maycontain components that are soluble in the hydrocarbon feed at thebeginning of processing. As properties of the hydrocarbon feed change(for example, API gravity, viscosity, MCR, C₅ asphaltenes, P-value, orcombinations thereof), the components may tend to become less soluble inthe hydrocarbon feed/total product mixture. In some instances, thehydrocarbon feed and the total product may form two phases and/or becomeinsoluble in one another. Solubility changes may also result in thehydrocarbon feed/total product mixture forming two or more phases.Formation of two phases, through flocculation of asphaltenes, change inconcentration of hydrocarbon feed and total product, and/orprecipitation of components, tends to reduce the life of one or more ofthe catalysts. Additionally, the efficiency of the process may bereduced. For example, repeated treatment of the hydrocarbon feed/totalproduct mixture may be necessary to produce a crude product with desiredproperties.

During processing, the P-value of the hydrocarbon feed/total productmixture may be monitored and the stability of the process, hydrocarbonfeed, and/or hydrocarbon feed/total product mixture may be assessed.Typically, a P-value that is at most 1.0 indicates that flocculation ofasphaltenes from the hydrocarbon feed generally occurs. If the P-valueis initially at least 1.0, and such P-value increases or is relativelystable during contacting, then this indicates that the hydrocarbon feedis relatively stabile during contacting. Hydrocarbon feed/total productmixture stability, as assessed by P-value, may be controlled bycontrolling contacting conditions, by selection of catalysts, byselective ordering of catalysts, or combinations thereof. Suchcontrolling of contacting conditions may include controlling LHSV,temperature, pressure, hydrogen uptake, hydrocarbon feed flow, orcombinations thereof.

The accumulation of sediment and/or insoluble components in the reactormay lead to a pressure change in the contacting zone, thus inhibitinghydrocarbon feed from passing through the contacting zone at desiredflow rates. A rapid increase in pressure may indicate plugging of thecatalyst. A change in pressure of at least 3 MPa, at least 5 MPa, atleast 7 MPa, or at least 10 MPa over a short period of time may indicatecatalyst plugging.

During processing, the inlet pressure of a contacting zone of a fixedbed reactor may be monitored. A rapid increase in inlet pressure mayindicate that flow through the catalyst is inhibited. The inhibition offlow may be caused by an increase in deposit or sediment formation. Theincrease in deposit or sediment may plug pores of the catalyst, thusrestricting flow of the hydrocarbon feed through the contacting zone.

Typically, hydrocarbon feed having viscosities that inhibit thehydrocarbon feed from being transported and/or pumped are contacted atelevated hydrogen pressures (for example, at least 7 MPa, at least 10MPa or at least 15 MPa) to produce products that are more fluid. Atelevated hydrogen pressures coke formation is inhibited, thus theproperties of the hydrocarbon feed may be changed with minimal cokeproduction. Since reduction of viscosity, residue and C₅/C₇ asphaltenesis not dependent on hydrogen pressure, reduction of these properties maynot occur unless the contacting temperature is at least 300° C. For somehydrocarbon feeds, temperatures of at least 350° C. may be required toreduce desired properties of the hydrocarbon feed to produce a productthat meets the desired specifications. At increased temperatures cokeformation may occur, even at elevated hydrogen pressures. As theproperties of the hydrocarbon feed are changed, the P-value of thehydrocarbon feed/total product may decrease below 1.0 and/or sedimentmay form, causing the product mixture to become unstable. Since,elevated hydrogen pressures require large amounts of hydrogen, a processcapable of reducing properties that are independent of pressure atminimal temperatures is desirable. A process that operates at pressuresof at most 7 MPa and temperatures of at least 200° C. without producingsediment and/or coke are advantageous.

During contact, the P-value may be kept above 1.0 by controlling thecontacting temperature. For example, in some embodiments, if thetemperature increases above 450° C., the P-value drops below 1.0 and thehydrocarbon feed/total product mixture becomes unstable. If thetemperature decreases below 370° C., minimal changes to the hydrocarbonfeed properties occurs.

The crude product produced by contacting a hydrocarbon feed with one ormore catalysts described herein may be useful in a wide range ofapplications including, but not limited to, use as a feed to refineries,feed for producing transportation fuel, a diluent, or an enhancing agentfor underground oil recovery processes. For example, hydrocarbon feedshaving an API gravity of at most 10 (for example, bitumen and/or heavyoil/tar sands crude) may be converted into various hydrocarbon streamsthrough a series of processing steps using cracking units (for example,an ebullating bed cracking unit, a fluid catalytic cracking unit,thermal cracking unit, or other units known to convert hydrocarbon feedto lighter components).

Reduction of the viscosity content of a hydrocarbon feed to produce afeed stream that may be processed in units may enhance the processingrate of hydrocarbon feed. A system using the methods and catalystsdescribed herein to change properties of a hydrocarbon feed may bepositioned upstream of one or more of the cracking units. Treatment ofthe hydrocarbon feed in one or more systems described herein may producea feed that improves the processing rate of the cracking unit by atleast a factor of 2, at least a factor of 4, at least a factor of 10, orat least a factor of 100. For example, a system for treating ahydrocarbon feed having a viscosity of at least 100 cSt at 37.8° C.and/or 0.1 grams of residue per gram of hydrocarbon feed may include oneor more contacting systems described herein positioned upstream of acracking unit. The contacting system may include one or more catalystsdescribed herein capable of producing a crude product having a viscosityof at most 50% of the viscosity of the hydrocarbon feed at 37.8° C.and/or at most 90% of the residue of the hydrocarbon feed. The crudeproduct and/or a mixture of the crude product and hydrocarbon feed mayenter the cracking unit. Since the crude product and/or mixture of thecrude product and hydrocarbon feed has a lower viscosity than theoriginal hydrocarbon feed, the processing rate through the cracking unitmay be improved.

In some embodiments, hydrocarbon feeds having at least 0.01 grams of C₅asphaltenes may be deasphalted prior to hydroprocessing treatment in arefinery operation. Deasphalting processes may involve solventextraction and/or contacting the crude with a catalyst to removeasphaltenes. Reduction of at least a portion of the components thatcontribute to viscosity, at least a portion of the components thatcontribute to residue and/or asphaltenes prior to the deasphaltingprocess may eliminate the need for solvent extraction, reduce the amountof required solvent, and/or enhance the efficiency of the deasphaltingprocess. For example, a system for treating a hydrocarbon feed having,per gram of hydrocarbon feed, at least 0.01 grams of C₅ asphaltenesand/or 0.1 grams of residue and a viscosity of at least 10 cSt at 37.8°C. may include one or more contacting systems described hereinpositioned upstream of a deasphalting unit. The contacting system mayinclude one or more catalysts described herein capable of producing acrude product having a C₅ asphaltenes content of at most 50% of thehydrocarbon feed C₅ asphaltenes content, a residue content of at most90% of the hydrocarbon feed residue content, a viscosity of at most 50%of the hydrocarbon viscosity or combinations thereof. The crude productand/or a mixture of the crude product and hydrocarbon feed may enter thedeasphalting unit. Since the crude product and/or mixture of the crudeproduct and the hydrocarbon feed has a lower asphaltene, residue and/orviscosity than the original hydrocarbon feed, the processing efficiencyof the deasphalting unit may be increased by at least 5%, at least 10%,at least 20% or at least 50% of the original efficiency.

EXAMPLES

Non-limiting examples of catalyst preparations and methods of using suchcatalysts under controlled contacting conditions are set forth below.

Example 1 Preparation of a Column 6 Metal Catalyst Having at Most 10 Wt% Molybdenum and a Surface Area of at least 340 m²/g

A support (4103.4 grams) that contained 0.02 grams of silica and 0.98grams alumina per gram of support was combined with molybdenum trioxide(409 grams) to form a Mo/support mixture. With a muller mixer running,deionized water (2906.33 grams) was added to the Mo/support mixture andthe mixture was mulled until a loss on ignition (after 1 hour at 700°C.) of 58% was obtained. During comulling, the compactness of the powderwas monitored every 20 to 30 minutes and 1 wt % (based on loss ofignition) of deionized water was added to the mixture until the loss onignition value was obtained. The pH of the compact Mo/support powder was4.63.

The compact Mo/support powder was extruded using 1.3 mm trilobe dies toform 1.3 mm trilobe extrudate particles. The extruded particles weredried at 125° C. and then calcined at 537° C. (1000° F.) for two hoursto form the catalyst. The bulk density of the catalyst was 0.547 g/mL.The resulting catalyst contained, per gram of catalyst, 0.08 grams ofmolybdenum, with the balance being support. The molybdenum catalyst is amonomodal catalyst having a median pore diameter of 81 Å, with at least60% of the total number of pores in the pore size distribution having apore diameter within 33 Å of the median pore diameter, a pore volume of0.633 mL/g, and a surface area of 355 m²/g. The pore distribution asmeasured by mercury porosimetry at contact angle of 140 is shown inTABLE 1.

TABLE 1 Pore Diameter in Å % Pore Volume <70  25.61  70-100 57.76100-130 8.96 130-150 1.50 150-300 4.38  300-5000 2.44 >5000 0.47

Example 2 Preparation of a Column 6 Metal Catalyst Having at Least 10 wt% Molybdenum and a Surface Area of at least 340 m²/g

A support (3000 grams) that contained 0.02 grams of silica and 0.98grams alumina per gram of support was combined with molybdenum trioxide(797.84 grams) to form a Mo/support mixture. With a muller running,deionized water (4092.76 grams) was added to the Mo/support mixture, andthe mixture was mulled until a loss of ignition of 0.5787 grams per gramof mixture was obtained (for about 45 minutes). The pH of the Mo/supportmixture was 3.83.

The Mo/support mixture was extruded using 1.3 mm trilobe dies to form1.3 trilobe extrudate particles. The particles were dried at 125° C. andthen calcined at 537° C. (1000° F.) for two hours. The compacted bulkdensity of the extrudates was 0.545 g/mL. The resulting catalystcontained, per gram of catalyst, 0.133 grams of molybdenum, with thebalance being support. The molybdenum catalyst is a monomodal catalysthaving a median pore diameter of 88 Å, with at least 60% of the totalnumber of pores in the pore size distribution having a pore diameterwithin 47 Å of the median pore diameter, a pore volume of 0.651 mL/g,and a surface area of 365 m²/g. The pore distribution as measured bymercury porosimetry at a contact angle of 140 is shown in TABLE 2.

TABLE 2 Pore Diameter in Å % Pore Volume <70  23.58  70-100 40.09100-130 12.77 130-150 3.02 150-180 2.56 180-300 4.04  300-1000 4.531000-3000 5.16 3000-5000 3.19 >5000 1.04

FIG. 2 shows x-ray diffraction plots of intensity versus degrees 2-Thetaof molybdenum trioxide and the catalyst as prepared in Examples 1 and 2.Plot 112 represents the spectrum of molybdenum trioxide. Plot 114represent the spectrum of the catalyst as prepared in Example 1. Plot116 represent the spectrum of the catalyst as prepared in Example 2.Peaks between 35 degrees 2-Theta and 70 degree 2-theta have peak widthsof about 10 degree 2-theta. Distinct peaks for molybdenum trioxidebetween 10 degrees 2-theta and 30 degrees 2-theta are absent from plots114, 116. Plots 114, 116 are similar to the x-ray diffraction patternfor alumina. The change from sharp peaks for molybdenum trioxide (plot112) to substantially no peaks or broad peaks (plots 114, 116) indicatesthat the molybdenum metal is moving inside the alumina cavities andcannot be detected by x-ray diffraction techniques.

Examples 1 and 2 demonstrate a method of making a catalyst that includescontacting one or more oxides of one or more Column 6 metals of thePeriodic Table with a support, and calcining the one or more Column 6metal oxides and support at a temperature from 315° C. to 760° C. toprovide a calcined catalyst. The support comprises from 0.01 grams to0.2 gram of silica and from 0.8 grams to 0.99 grams of alumina per gramof support. The calcined catalyst has a surface area of at least 340m²/g, a pore size distribution with a median pore diameter of at most100 Å, and at least 80% of its pore volume in pores having a porediameter of at most 300 Å.

Examples 1 and 2 also demonstrate a catalyst that includes one or moremetals from Column 6 of the Periodic Table and/or one or more compoundsof one or more metals from Column 6 of the Periodic Table and a support;wherein the support comprises from 0.01 grams to 0.2 grams of silica andfrom 0.80 grams to 0.99 grams of alumina per gram of support, andwherein the catalyst has a surface area of at least 340 m²/g, a poresize distribution with a median pore diameter of at most 100 Å, and atleast 80% of its pore volume in pores having a pore diameter of at most300 Å.

Example 3 Catalyst Having a Surface Area of at Most 250 m²/g

A comparative catalyst was prepared in the following manner. MoO₃ (94.44grams) was combined with wide pore alumina (2742.95 grams) and crushedand sieved alumina fines having a particle size between 5 and 10micrometers (1050.91 grams) in a muller. With the muller running, nitricacid (43.04 grams, 69.7 M) and deionized water (4207.62 grams) wereadded to the mixture and the resulting mixture was mulled for 5 minutes.Superfloc® 16 (30 grams, Cytec Industries, West Paterson, N.J., USA) wasadded to the mixture in the muller, and the mixture was mulled for atotal of 25 minutes. The resulting mixture had a pH of 6.0 and a loss onignition of 0.6232 grams per gram of mixture. The mulled mixture wasextruded using 1.3 mm trilobe dies to form 1.3 trilobe extrudateparticles. The extrudate particles were dried at 125° C. for severalhours and then calcined at 676° C. (1250° F.) for two hours to producethe catalyst. The catalyst contained, per gram of catalyst, 0.02 gramsof molybdenum, with the balance being mineral oxide and support. Thecatalyst is a bimodal catalyst having a pore size distribution with amedian pore diameter of 117 Å with 60% of the total number of pores inthe pore size distribution having a pore diameter within 33 Å of themedian pore diameter, a total pore volume of 0.924 cc/g, and a surfacearea of 249 m²/g.

The pore size distribution measured using mercury porosimetry at acontact angle of 140 is shown in TABLE 3.

TABLE 3 Pore Diameter in Å % Pore Volume <70  0.91  70-100 20.49 100-13037.09 130-150 4.51 150-180 2.9 180-200 1.06  200-1000 0.85 1000-50005.79 >5000 22.04

Example 4 Contact of a Hydrocarbon Feed with Catalysts from Examples 1and 3

A tubular reactor with a centrally positioned thermowell was equippedwith thermocouples to measure temperatures throughout a catalyst bed.The catalyst bed was formed by filling the space between the thermowelland an inner wall of the reactor with catalysts and silicon carbide(20-grid, Stanford Materials; Aliso Viejo, Calif.). Such silicon carbideis believed to have low, if any, catalytic properties under the processconditions described herein. All catalysts were blended with an equalvolume amount of silicon carbide before placing the mixture into thecontacting zone portions of the reactor.

The hydrocarbon feed flow to the reactor was from the top of the reactorto the bottom of the reactor. Silicon carbide was positioned at thebottom of the reactor to serve as a bottom support.

A volume of Column 6 metal catalyst (24 cm³) as described in Example 1was mixed with silicone carbide (24 cm³) and the mixture was positionedin the bottom contacting zone.

A Column 6 metal catalyst (6 cm³) as described in Example 3 was mixedwith silicone carbide (6 cm³) and the mixture was positioned on top ofthe contacting zone to form a top contacting zone.

The catalysts were sulfided by introducing a gaseous mixture of 5 vol %hydrogen sulfide and 95 vol % hydrogen gas into the contacting zones ata rate of 1.5 liters/hour of gaseous mixture per volume (mL) of totalcatalyst (silicon carbide was not counted as part of the volume ofcatalyst). Temperatures of the contacting zones were increased to 204°C. (400° F.) over 1 hour and held at 204° C. for 2 hours. After holdingat 204° C., the temperature of the contacting zones was increasedincrementally to 316° C. (600° F.) at a rate of 10° C. (50° F.) perhour. The contacting zones were maintained at 316° C. for an hour, thenthe temperature was raised to 370° C. (700° F.) over 1 hour and held at370° C. for two hours. The contacting zones were allowed to cool toambient temperature.

After sulfidation of the catalysts, the temperature of the contactingzones was raised to a temperature of 410° C. A hydrocarbon feed (PeaceRiver), having the properties listed in Table 4 was flowed through thepreheat zone, top contacting zone, bottom contacting zone, and bottomsupport of the reactor. The hydrocarbon feed was contacted with each ofthe catalysts in the presence of hydrogen gas. Contacting conditionswere as follows: ratio of hydrogen gas to feed was 318 Nm³/m³ (2000SCFB) and LHSV was about 0.5 h⁻¹. The two contacting zones were heatedto 400° C. and maintained between 400° C. and 420° C. at a systempressure of 3.5 MPa (500 psig) as the hydrocarbon feed flowed throughthe reactor for a period of time (about 9722 hours). During the run, anincrease in inlet pressure from about 3.5 MPa and about 7 MPa wasobserved at about 6500 hours and 9000 hours. Although the pressureincreased during this time, the pressure stabilized at about 7 MPa.Since a rapid increase in pressure was not observed the run was allowedto continue. The P-Value was monitored periodically and remained at 1.0or above 1.0, therefore the process was considered stable. For example,at 7896 hours the P-Value was 1.0 and the inlet pressure was about 7.1MPa (1012 psig). At about 9000 hours, the inlet pressure dropped tobelow 7 MPa.

As shown in Table 4, the crude product had a viscosity of 79.5 at 37.8°C., a residue content of 0.278 grams, per gram of crude product, aNi/V/Fe content of 252.6 wtppm, a molybdenum content of 0.4 wtppm, and aMCR content of 10.4.

This example demonstrates a method for contacting a hydrocarbon feedwith one or more catalysts to produce a total product that includes thecrude product. At least one of the catalysts comprises one or moremetals from Column 6 of the Periodic Table and/or one or more compoundsof one or more metals from Column 6 of the Periodic Table and a support.The support comprises from 0.01 grams to 0.2 gram of silica and from0.80 grams to 0.99 grams of alumina per gram of support. The Column 6metal catalyst has a surface area of at least 340 m²/g, a pore sizedistribution with a median pore diameter of at most 100 Å, and at least80% of its pore volume in pores having a pore diameter of at most 300 Å.

This example also demonstrates a method for contacting a hydrocarbonfeed with one or more catalyst to produce a total product that includesthe crude product. At least one of the catalysts comprises one or moremetals from Column 6 of the Periodic Table and/or one or more compoundsof one or more metals from Column 6 of the Periodic Table and a support.The support comprises from 0.01 grams to 0.2 gram of silica and from0.80 grams to 0.99 grams of alumina per gram of support. The catalystexhibits one or more peaks between 35 degrees and 70 degrees, and atleast one of the peaks has a base width of at least 10 degrees, asdetermined by x-ray diffraction at 2-theta.

Example 5 Contact of a Hydrocarbon Feed Catalysts from Examples 2 and 3

The apparatus, sulfiding of catalyst, hydrocarbon feed and operatingconditions were the same as for Example 4, with the exception of thecatalysts.

A volume of Column 6 metal catalyst (24 cm³) as described in Example 2was mixed with silicone carbide (24 cm³) and the mixture positioned inthe bottom contacting zone.

A Column 6 metal catalyst (6 cm³) as described in Example 3 was mixedwith silicone carbide (6 cm³) and the mixture positioned on top of thecontacting zone to form a top contacting zone.

During the run, a rapid increase in inlet pressure from about 3.5 MPaand about 10.4 MPa was observed at about 6500 hours. Since the pressuredid not stabilize, the run was stopped.

As shown in Table 4, the crude product had a viscosity of 86.4 at 37.8°C., a residue content of 0.264 grams, per gram of crude product, aNi/V/Fe content of 251.6 wtppm, a molybdenum content of 0.4 wtppm, and aMCR content of 10.6.

This example demonstrates that a method for contacting a hydrocarbonfeed with one or more catalysts to produce a total product that includesthe crude product. At least one of the catalysts comprises one or moremetals from Column 6 of the Periodic Table and/or one or more compoundsof one or more metals from Column 6 of the Periodic Table and a support.The support has from 0.01 grams to 0.2 gram of silica and from 0.80grams to 0.99 grams of alumina per gram of support. The Column 6 metalcatalyst has a surface area of at least 340 m²/g, a pore sizedistribution with a median pore diameter of at most 100 Å, and at least80% of its pore volume in pores having a pore diameter of at most 300 Å.

This example also demonstrates a method for contacting a hydrocarbonfeed with one or more catalyst to produce a total product that includesthe crude product. At least one of the catalysts comprises one or moremetals from Column 6 of the Periodic Table and/or one or more compoundsof one or more metals from Column 6 of the Periodic Table and a support.The support comprises from 0.01 grams to 0.2 gram of silica and from0.80 grams to 0.99 grams of alumina per gram of support. The catalystexhibits one or more peaks between 35 degrees and 70 degrees, and atleast one of the peaks has a base width of at least 10 degrees, asdetermined by x-ray diffraction at 2-theta.

FIG. 3 is a graphical representation of P-value of the crude productversus run time for each of the catalyst systems of Examples 4 and 5.The hydrocarbon feed had a P-value of at least 1.2. Plots 118 and 120represent the P-value of the crude product obtained by contacting thehydrocarbon feed with the three catalyst systems of Examples 4 and 5respectively. From the P-value of the crude product for each trial, itmay be inferred that the hydrocarbon feed in each trial remainedrelatively stable during contacting (for example, the hydrocarbon feeddid not separate into separate phases). As shown in FIG. 3, the P-valueof the crude product remained relatively constant during significantportions of each trial.

Example 6 Comparative Example

The apparatus, sulfiding of catalyst, hydrocarbon feed and operatingconditions were the same as for Example 4, with the exception of thecatalysts.

A volume of Column 6 metal catalyst (24 cm³) as described in Example 3was mixed with silicone carbide (24 cm³) and the mixture was positionedin the bottom contacting zone.

A Column 6 metal catalyst (6 cm³) as described in Example 3 was mixedwith silicone carbide (6 cm³) and the mixture was positioned on top ofthe contacting zone to form a top contacting zone.

Silicon carbide was positioned on top of the top contacting zone to filldead space and to serve as a preheat zone. The catalyst bed was loadedinto a Lindberg furnace that included four heating zones correspondingto the preheat zone, the top and bottom contacting zones, and the bottomsupport.

During the run, a increase in inlet pressure from about 3.5 MPa andabout 5 MPa was observed at about 5543 hours.

As shown in Table 4, the crude product had a viscosity of 101 at 37.8°C., a residue content of 0.273 grams, per gram of crude product, aNi/V/Fe content of 255.2 wtppm, a molybdenum content of 0.6 wtppm, and aMCR content of 10.6.

In comparing Examples 4 and 5 with the comparative Examples, the crudeproducts have similar values for all the Examples. The crude productsproduced in Examples 4 and 5 have lower values for viscosity andhydrogen consumption as compared to the respective values for the crudeproduct produced in the comparative example. As such, it may beconcluded that contact of the hydrocarbon feed with hydrogen in thepresence of the catalyst prepared as described in Examples 1 and 2 mayreduce viscosity of the hydrocarbon feed more than contact of thehydrocarbon feed with hydrogen in the presence of the catalyst preparedas described in Example 3.

Example 7 Comparative Example

The hydrocarbon feed, contacting conditions, and sulfidation were thesame as Example 4.

A commercial bimodal molybdenum/nickel catalyst (RM 5030, CriterionCatalysts & Technologies, Houston, Tex., 24 cm³) having a molybdenumcontent of about 5 wt %, a surface area of about 255 m²/g and having abimodal pore size distribution with a medium pore diameter of about 117Å used for upgrading residue was prepared mixed with silicone carbide(30 cm³ for a total catalyst/silicone carbide mixture of 54 cm³) waspositioned in the contacting zone. The run was terminated at 1872 hoursdue to a rapid increase in pressure change (inlet pressure of greaterthan 13 MPa (about 1872 psig) and rising. Rapid increase in inletpressure was attributed to catalyst plugging.

FIG. 4 is a graphical representation of inlet pressure of the reactorversus run time for catalysts in Examples 4-7, including the twoexamples of the process of the present invention and the two comparativeexamples. Data 122 represents Example 4, data 124 represents Example 5,data 126 represents Example 6, and data 128 represents Example 7.Although, an increase in pressure was observed at about 6500 hours forExample 4 (data 118), the pressure become substantially constant atabout 7 MPa and viscosity reduction in addition to other properties ofthe crude product were still modified as compared to the hydrocarbonfeed properties. No rapid increase in pressure was observed for thiscatalyst.

Example 5 showed a rapid increase in pressure at about 6500 hours. Incomparing Examples 4 and 5, the catalyst of Example 4 was observed tochange properties of the hydrocarbon feed for longer periods of timethan the catalyst of Example 5. The longer run time may be attributed tothe catalyst of Example 4 having less metal (less than 0.1 grams ofColumn 6 metal per gram of catalyst) as compared to the catalyst ofExample 5.

In comparing Examples 4 and 5 with the comparative examples (Example 6and Example 7) the crude products have similar values for all theExamples. The catalyst life for Examples 4 and 5 is significantly longerthan the catalyst life for the comparative examples. As such, it may beconcluded that the contact of the hydrocarbon feed with hydrogen in thepresence of the monomodal catalyst prepared as described in Examples 1and 2 may be done at low pressures and high temperatures for longerperiods of time than the comparative catalysts at the same temperaturesand pressures.

TABLE 4 Crude Product Example Hydrocarbon Comparative ComparativeProperty Feed 4 4 5 Example 6 Example 7 Contact Time, 4200 8520 65365543 1872 hours Temperature, 410 410 410 410 410 ° C. Pressure, MPa 3.57 3.5 3.5 3.5 API Gravity 7.9 14.3 * 13.5 13.5 15.8 Density at 1.01490.9704 * 0.9785 0.9785 0.9608 15.56° C. (60° F.), g/cm³ Hydrogen, wt %10.109 10.432 10.720 10.485 10.403 10.617 Carbon, wt % 81.987 84.17484.450 83.72 84.513 84.617 Sulfur, wt % 6.687 4.387 3.714 5.064 4.4873.782 Nitrogen, wt % 0.366 0.399 0.371 0.397 0.397 0.385 Nickel, wtppm70 63 32 63 55 56 Iron, wtppm 2.4 0.6 0.2 0.4 0.2 0.2 Vanadium, 205 189100 197 151 152 wtppm Calcium, 6.7 5.9 0.3 0.7 1.9 2.1 wtppm Copper,wtppm 0.9 0.2 0.2 0.4 0.9 0.2 Chromium, 0.3 0.2 0.2 0.2 0.2 0.2 wtppmSilicon, wtppm 1.2 0.8 0.4 0.3 0.3 0.3 Magnesium, 0.8 0.7 0.2 0.6 0.20.4 wtppm Zinc, wtppm 6.0 1.0 0.6 2.0 1.4 1.7 Molybdenum, 6.6 0.4 1.91.9 0.3 0.8 wtppm Micro-Carbon 12.5 10.4 8.6 10.8 10.3 9.6 Residue, wt %C₅ Asphaltenes, 16.2 9 6.6 8.5 8.5 8.0 wt % C₇ Asphaltenes, 10.9 5.9 4.66.5 5.9 5.1 wt % Naphtha,, wt % 4.2 8.0 3.6 0.9 5.1 Distillate, wt %15.0 28.1 30.9 25.6 31.8 30.7 VGO, wt % 37.5 39.9 38.1 42.5 44.5 39.8Residue, wt % 47.4 27.8 23.0 28.9 22.8 24.4 P-Value 2.6 1.2 * 1.2 0.91.0 Viscosity at 8357 79.5 25.9 115 89.4 51.4 37.8° C. (100° F.), cStHydrogen 29.41 61.18 36.24 21.6 * Consumption, Nm³/m³ Inlet pressure3.78 7.2 8.7 3.6 8.2 * Not Determined

What is claimed is:
 1. A hydrocarbon composition, comprising: a totalNi/Fe/V content of at least 200 wtppm as determined by ASTM MethodD5708; a residue content of at least 0.2 grams per gram of hydrocarboncomposition as determined by ASTM Method D5307; a distillate content ofat least 0.2 grams per gram of hydrocarbon composition as determined byASTM Method D5307; a sulfur content of at least 0.04 grams per gram ofhydrocarbon composition as determined by ASTM Method D4294; and amicro-carbon residue content of at least 0.06 grams per gram ofhydrocarbon composition, as determined by ASTM Method D4530; and whereinthe hydrocarbon composition has a viscosity of at most 100 cSt at 37.8°C. as determined by ASTM Method D445.
 2. A transportation fuelcomprising one or more distillate fractions produced from thehydrocarbon composition as claimed in claim
 1. 3. A diluent producedfrom the hydrocarbon composition as claimed in claim 1.